Oil & Gas Wells
To produce oil or gas from a reservoir, a well is drilled into a subterranean formation, which may be the reservoir or adjacent to the reservoir. Typically, a wellbore of a well must be drilled hundreds or thousands of feet into the earth to reach a hydrocarbon-bearing formation.
It is desirable to extend the production of wells and to avoid early abandonment when productivity decreases as a result of low natural permeability or formation damage.
Well Servicing and Well Fluids
Well services can include various types of treatments that are commonly performed in a wellbore or subterranean formation. For example, stimulation is a type of treatment performed to enhance or restore the productivity of oil or gas from a well. Even small improvements in fluid flow can yield dramatic production results.
Stimulation treatments fall into two main groups: hydraulic fracturing and matrix treatments. Fracturing treatments are performed above the fracture pressure of the subterranean formation to create or extend a highly permeable flow path between the formation and the wellbore. Fracturing treatments are often applied in treatment zones having poor natural permeability. Matrix treatments are performed below the fracture pressure of the formation. Matrix treatments are often applied in treatment zones having good natural permeability to counteract damage in the near-wellbore area.
Hydraulic Fracturing
The purpose of a hydraulic fracturing treatment is to provide an improved flow path for oil or gas to flow from the hydrocarbon-bearing formation to the wellbore. In addition, a fracturing treatment can facilitate the flow of injected treatment fluids from the well into the formation. A treatment fluid adapted for this purpose is sometimes referred to as a fracturing fluid. The fracturing fluid is pumped at a sufficiently high flow rate and pressure into the wellbore and into the subterranean formation to create or enhance one or more fractures in the subterranean formation. Creating a fracture means making a new fracture in the formation. Enhancing a fracture means enlarging a pre-existing fracture in the formation.
A newly-created or newly-extended fracture will tend to close together after the pumping of the fracturing fluid is stopped. To prevent the fracture from closing, a material is usually placed in the fracture to keep the fracture propped open and to provide higher fluid conductivity than the matrix of the formation. A material used for this purpose is referred to as a proppant.
A proppant is in the form of a solid particulate, which can be suspended in the fracturing fluid, carried downhole, and deposited in the fracture to form a proppant pack. The proppant pack props the fracture in an open condition while allowing fluid flow through the permeability of the pack. The proppant pack in the fracture provides a higher-permeability flow path for the oil or gas to reach the wellbore compared to the permeability of the matrix of the surrounding subterranean formation. This higher-permeability flow path increases oil and gas production from the subterranean formation.
A particulate for use as a proppant is usually selected based on the characteristics of size range, crush strength, and solid stability in the types of fluids that are encountered or used in wells. Usually, but not in all applications, a proppant should not melt, dissolve, or otherwise degrade from the solid state under the downhole conditions.
Acidizing
The purpose of acidizing is to dissolve acid-soluble materials. A treatment fluid including an aqueous acid solution is introduced into a subterranean formation to dissolve the acid-soluble materials. In this way, oil or gas can more easily flow from the formation into the well. In addition, an acid treatment can facilitate the flow of injected treatment fluids from the well into the formation.
Acidizing techniques can be carried out as acid fracturing procedures or matrix acidizing procedures.
In acid fracturing, an acidizing fluid is pumped into a formation at a sufficient pressure to cause fracturing of the formation and to create differential (non-uniform) etching of fracture conductivity. Depending on the rock of the formation, the acidizing fluid can etch the fractures faces, whereby flow channels are formed when the fractures close. The acidizing fluid can also enlarge the pore spaces in the fracture faces and in the formation.
In matrix acidizing, an acidizing fluid is injected from the well into the formation at a rate and pressure below the pressure sufficient to create a fracture in the formation.
Acidizing Sandstone or Carbonate Formations
Acidizing is commonly performed in sandstone and carbonate formations, however, the different types of formations can require that the particular treatments fluids and associated methods be quite different.
For example, sandstone formations tend to be relatively uniform in composition and matrix permeability. In sandstone, a range of stimulation techniques can be applied with a high degree of confidence to create conductive flow paths, primarily with hydraulic fracturing techniques, as known in the field.
In sandstone formations, acidizing primarily removes or dissolves acid soluble damage in the near-wellbore region. Thus, in sandstone formations acidizing is classically considered a damage removal technique and not a stimulation technique. An exception is with the use of specialized hydrofluoric acid compositions, which can dissolve the siliceous material of sandstone.
Carbonate formations tend to have complex porosity and permeability variations with irregular fluid flow paths. Although many of the treatment methods for sandstone formations can also be applied in carbonate formations, it can be difficult to predict effectiveness for increasing production in carbonate formations.
In carbonate formations, the goal is usually to have the acid dissolve the carbonate rock to form highly-conductive fluid flow channels in the formation rock. These highly-conductive channels are called wormholes. In acidizing a carbonate formation, calcium and magnesium carbonates of the rock can be dissolved with acid. A reaction between an acid and the minerals calcite (CaCO3) or dolomite (CaMg(CO3)2) can enhance the fluid flow properties of the rock.
In carbonate reservoirs, hydrochloric acid (HCl) is the most commonly applied stimulation fluid. Organic acids such as formic or acetic acid are used mainly as retarded-acid systems or in high-temperature applications. Stimulation of carbonate formations usually does not involve hydrofluoric acid, however, which is difficult to handle and commonly only used where necessary, such as in acidizing sandstone formations.
Greater details, methodology, and exceptions regarding acidizing can be found, for example, in “Production Enhancement with Acid Stimulation” 2nd edition by Leonard Kalfayan (PennWell 2008), SPE 129329, SPE 123869, SPE 121464, SPE 121803, SPE 121008, IPTC 10693, and the references contained therein.
Problems with Acid Fracturing
When the acid is injected above the fracture pressure of the formation being treated, the treatment is called acid fracturing or fracture acidizing. The object is to create a large fracture that serves as an improved flowpath through the rock formation. After such fractures are created, when pumping of the fracture fluid is stopped and the injection pressure drops, the fracture tends to close upon itself and little or no new flow path is left open after the treatment. Commonly, a proppant is added to the fracturing fluid so that, when the fracture closes, proppant remains in the fracture, holds the fracture faces apart, and leaves a flow path conductive to fluids. In addition to or alternatively to propping, an acid may be used as a component of the fracturing fluid. Depending on the rock of the formation, the acid can differentially etch the faces of the fracture, creating or exaggerating asperities, so that, when the fracture closes, the opposing faces no longer match up. Consequently they leave an open pathway for fluid flow.
A problem with this technique is that as the acid is injected it tends to react with the most reactive rock or the rock with which it first comes into contact. Thus, much of the acid is used up near the wellbore and is not available for etching of the fracture faces farther from the wellbore.
In addition, the acidic fluid follows the paths of least resistance, which are for example either natural fractures in the rock or areas of more permeable or more acid-soluble rock. Depending on the nature of the rock formation, this process can create long branched passageways in the fracture faces leading away from the fracture, usually near the wellbore. These highly conductive micro-channels are called “wormholes” and are very deleterious because subsequently-injected fracturing fluid tends to leak off into the wormholes rather than lengthening the desired fracture. To block the wormholes, techniques called “leak-off control” techniques have been developed. This blockage should be temporary, however, because the wormholes are preferably open to flow after the fracturing treatment; oils or gas production through the wormholes adds to total production.
Problems with Matrix Acidizing
When an acidic fluid is used to stimulate a substantially acid-soluble formation below the fracturing pressure, the treatment is called matrix acidizing. Studies have shown that the dissolution pattern created by the flowing acid occurs by one of three mechanisms (a) compact dissolution, in which most of the acid is spent near the wellbore rock face; (b) wormholing, in which the dissolution advances more rapidly at the tips of a small number of wormholes than at the wellbore walls; and (c) uniform dissolution, in which many pores are enlarged. Compact dissolution occurs when acid spends on the face of the formation. In this case, the live acid penetration is commonly limited to within a few centimeters of the wellbore. Uniform dissolution occurs when the acid reacts under the laws of fluid flow through porous media. In this case, the live acid penetration will be, at most, equal to the volumetric penetration of the injected acid. (Uniform dissolution is also the preferred primary mechanism of conductive channel etching of the fracture faces in acid fracturing, as discussed above.) The objectives of the matrix acidizing process are met most efficiently when near wellbore permeability is enhanced to the greatest depth with the smallest volume of acid. This occurs in regime (b) above, when a wormholing pattern develops.
However, just as wormholing prevents the growth of large fractures, wormholing prevents the uniform treatment of long zones of a formation along a wellbore. Once wormholes have formed, at or near a point in the soluble formation where the acid first contacts the formation, subsequently-injected acid will tend to extend the existing wormholes rather than create new wormholes further along the formation. Temporary blockage of the first wormholes is needed so that new wormholes can be formed and the entire section of the formation treated. This is called “diversion,” as the treatment diverts later-injected acid away from the pathway followed by earlier-injected acid. In this case, the blockage must be temporary because all the wormholes are desired to serve as production pathways.
Corrosion Problems with Using Acids in Well Fluids
Although acidizing a portion of a subterranean formation can be very beneficial in terms of permeability, the use of acidizing fluids can have significant drawbacks. Even weakly acidic fluids can be problematic in that they can cause corrosion of metals. Corrosion can occur anywhere in a well production system or pipeline system, including anywhere downhole in a well or in surface lines and equipment.
The expense of repairing or replacing corrosion-damaged equipment is extremely high. The corrosion problem is exacerbated by the elevated temperatures encountered in deeper formations. The increased corrosion rate of the ferrous and other metals comprising the tubular goods and other equipment results in quantities of the acidic solution being neutralized before it ever enters the subterranean formation, which can compound the deeper penetration problem discussed above. In addition, the partial neutralization of the acid from undesired corrosion reactions can result in the production of quantities of metal ions that are highly undesirable in the subterranean formation.
Leak-off Control or Matrix Diversion
In subterranean treatments in conventional reservoirs, it is often desired to treat a zone of a subterranean formation having sections of varying permeability, varying reservoir pressures, or varying degrees of formation damage, and thus may accept varying amounts of certain treatment fluids. Low reservoir pressure in certain areas of a subterranean formation or a rock matrix or a proppant pack of high permeability may permit that portion to accept larger amounts of certain treatment fluids. It may be difficult to obtain a uniform distribution of the treatment fluid throughout the entire zone. For instance, the treatment fluid may preferentially enter portions of the zone with low fluid flow resistance at the expense of portions of the zone with higher fluid flow resistance. Matrix diversion is different from zonal diversion between different zones.
Similar fluids and methods can be used for “leak-off control” in acid fracturing and for “diversion” in matrix acidizing Such a method or acidic fluid may be termed a “leak-off control acid system” or a “self-diverting acid system” depending upon its use and purpose.
Increasing the viscosity or gelling of a fluid can help divert subsequently introduced fluid from higher permeability to lower permeability portions of a zone. This can be useful for leak-off control in acid fracturing or matrix diversion in matrix acidizing
A viscosity-increasing agent is sometimes referred to in the art as a viscosifying agent, viscosifier, thickener, gelling agent, or suspending agent. In general, any of these refers to an agent that includes at least the characteristic of increasing the viscosity of a fluid in which it is dispersed or dissolved. There are several kinds of viscosity-increasing agents and related techniques for increasing the viscosity of a fluid.
Breaking Fluid Viscosity or Gel
After a treatment fluid is placed where desired in the well and for the desired time, the viscous fluid or gel usually must be removed from the wellbore or the formation to allow for the production of oil or gas. To accomplish this removal, the viscosity of the treatment fluid must be reduced to a very low viscosity, preferably near the viscosity of water, for optimal removal from the zone of the subterranean formation.
Reducing the viscosity of a viscosified fluid is referred to as “breaking” the fluid. Chemicals used to reduce the viscosity of fracturing fluids are called “breakers.”
No particular mechanism is necessarily implied by the term. A breaker or breaking mechanism should be selected based on its performance in the temperature, pH, time, and desired viscosity profile for each specific treatment.
Damage to Permeability
In well treatments using viscous well fluids, the material for increasing the viscosity of the fluid can damage the permeability of the proppant pack or the matrix of the subterranean formation. For example, a treatment fluid can include a polymeric material that is deposited in the fracture or within the matrix. By way of another example, the fluid may include surfactants that lead to sludge formation or change the wettability of the formation in the region of the fracture.
Viscoelastic Surfactants for Increasing Viscosity
Surfactants are compounds that lower the surface tension of a liquid, the interfacial tension between two liquids, or that between a liquid and a solid. Surfactants may act as detergents, wetting agents, emulsifiers, foaming agents, and dispersants.
Surfactants are usually organic compounds that are amphiphilic, meaning they contain both hydrophobic groups (“tails”) and hydrophilic groups (“heads”). Therefore, a surfactant contains both a water-insoluble (or oil soluble) portion and a water-soluble portion.
A “surfactant package” can include one or more different chemical surfactants.
In a water phase, surfactants form aggregates, such as micelles, where the hydrophobic tails form the core of the aggregate and the hydrophilic heads are in contact with the surrounding liquid. The aggregates can be formed in various shapes such as spherical or cylindrical micelles or bilayers. The shape of the aggregates depends on the chemical structure of the surfactants, depending on the balance of the sizes of the hydrophobic tail and hydrophilic head.
As used herein, the term “micelle” includes any structure that minimizes the contact between the lyophobic (“solvent-repelling”) portion of a surfactant molecule and the solvent, for example, by aggregating the surfactant molecules into structures such as spheres, cylinders, or sheets, wherein the lyophobic portions are on the interior of the aggregate structure and the lyophilic (“solvent-attracting”) portions are on the exterior of the structure.
Certain types of surfactants can impart viscosity and elasticity to a fluid. Such a surfactant is referred to as a “viscoelastic surfactant” (“VES”). When used as a viscosity-increasing agent, the molecules (or ions) of the surfactant associate to form micelles of a certain micellar structure (e.g., rod-like, worm-like, vesicles, etc., which are referred to herein as “viscosifying micelles”) that, under certain conditions (e.g., concentration, ionic strength of the fluid, etc.) are capable of, inter alia, imparting increased viscosity to a particular fluid or forming a gel. Certain viscosifying micelles may impart increased viscosity to a fluid such that the fluid exhibits viscoelastic behavior (e.g., shear thinning properties) due, at least in part, to the association of the surfactant molecules contained therein.
Viscoelastic Surfactants in Acidizing
The various types of cross-linked polymeric fluids that are commonly used in the treatment. However, such cross linked fluids are known to leave solid residue after the treatment and thereby damage the formation.
There are certain VES fluids that develop viscosity after the acid starts to spend. This results in better diversion that can be considered as another advantage of the VES fluid. The acid diversion is very important in acid stimulation treatment to enhance oil production by creating better wormholes. It also increases the depth of penetration of acid into the reservoir.
The viscoelastic surfactant fluids are gaining importance due to their less-damaging nature towards the formation as compared to crosslinked polymer fluids. The VES fluids develop viscosity by aggregation of surfactants molecules that shows similar properties of polymers. The VES fluid breaks down easily on dilution or contact with oil, thereby leaving negligible residue in the reservoir. The viscosity of a VES fluid depends on various factors such as the structure of the surfactant, nature of the counter ion, temperature, and presence of water-insoluble components.
The main limitation of VES fluids is the steep decrease in viscosity with increase in temperature that limits it application for high-temperature reservoirs. At present, known VES fluids can work only up to about 93° C. (200° F.) and cannot be used for higher temperatures. Hence there was a need to develop a VES fluid that will show good rheological properties at temperatures in the range of 93° C. (200° F.) to 150° C. (300° F.).
Since the VES fluid is pumped as a live acid, the incorporation of appropriate corrosion inhibitor is important to protect tubulars in a well. Unfortunately, corrosion inhibitors tend to interfere with the function of the VES. The formulated VES fluid should pass the corrosion test in live acid. The same fluid with spent acid should also show good rheology in the presence of the corrosion inhibitor at specified temperature. Hence there was also a need to develop a VES fluid that will show good rheological properties at temperatures above 93° C. (200° F.) with the inclusion of a corrosion inhibitor.